Annulus plugging detection using a pressure transmitter in gas-lift oil production

ABSTRACT

Outer annulus plugging detection is provided for gas-lift oil wells. The outer annulus detection is effected using a pressure transmitter. The pressure transmitter provides an indication of pressure within an outer annulus of the oil well. A statistical parameter related to a plurality of outer annulus pressure readings is used to provide an indication of annulus plugging. Examples of the statistical parameter include mean and standard deviation.

CROSS-REFERENCE TO RELATED APPLICATION

The present application is based on and claims the benefit of U.S.provisional patent application Ser. No. 60/542,185, filed Feb. 5, 2004,the content of which is hereby incorporated by reference in itsentirety.

BACKGROUND OF THE INVENTION

The present invention is related to gas-lift oil production operations.More particularly, the present invention is related to improved annulusplugging detection in such operations.

The gas-lift method of lifting crude oil is used in many of the world'soil wells. Indeed, in fields where significant quantities of associatedgas are present and produced solids are involved, it is the preferredmethod of augmenting the natural reservoir pressure and thus increasingproduction.

Because the technique involves comparatively compact equipment at thewell head, it is especially attractive where space is at a premium, suchas offshore, and where access for maintenance is restricted.

FIG. 1 is diagrammatic view of a typical gas-lift oil well. Central pipe10 defines a passageway 12 through which crude oil flows in thedirection of arrow 14 up to the ground and ultimately to one or morecollection stations. The middle section includes middle conduit 16disposed preferably, concentrically, about pipe 10 to define an innerannulus 17 between conduit 16 and pipe 10. Pressurized gas is injectedinto inner annulus 17 and travels down, in the direction of arrow 18, tothe bottom of the piping. The pressurized gas then enters the middlesection that contains the crude oil through a special section. Thiscreates lift for the crude oil to ascend via pipe 10 to the surface. Bythe nature of this process, inner annulus 17 is highly pressurized andoften has temperatures exceeding that of ambient. An outer shell 20defines an outer annulus 22 between shell 20 and conduit 16. Outerannulus 22 and shell 20 help protect the environment against leaks andany thermal impacts of the pumping operation. In an ideal situation, thepressure within outer annulus 22 is slightly below atmospheric pressureand would not have any materials, such as oil or gas, disposed therein.However, in actual operations, outer annulus 22 may become pressurizeddue to leaks from inner annulus 17 or cracks in conduit 16 defining thebarrier between inner annulus 17 and outer annulus 22. The pressurewithin outer annulus may sometimes reach levels on the order of 2000pounds per square inch. In these cases, a special permit may be requiredfrom the state, or other suitable regulatory authority, to operate thewell. In such situations, the pressure within outer annulus 22 must bemonitored to comply with regulations.

One factor that complicates monitoring the pressure within outer annulus22 is material disposed within annulus 22, which may become filled(partially or fully) with materials such as water, mud, oil from thesurroundings or from the reservoir. The presence of these materials cancreate a significant problem for pressure measurement because they mayfreeze at relatively high temperatures due to the significant pressuresinvolved. As illustrated in FIG. 1, a pressure transmitter, such astransmitter 24 is sometimes operably coupled to outer annulus 22 inorder to monitor the pressure therein.

During normal oil pumping operations, the well temperature may be around160° F., which is induced by the relatively high-pressure gas injectionto the system. Due to various reasons, the well may stop operationoccasionally. In this case, the well temperature close to ground andwell head above ground will drop in temperature to that of ambient. Inthese cases, the material inside outer annulus 22 can freeze creating aplug in annulus 22 and/or instrument piping 26. When this happens,pressure measurements taken using transmitter 24 will no longer reflectthe actual pressures in outer annulus 22. When the well starts tooperate again, the temperature in the well starts to rise. Thistemperature rise will cause expansion of the material in the bottomsections of annulus 22. Since there may be a frozen plug at the topsection, significant increases in pressure in annulus 22 below the plugcan occur. Outer annulus pressures exceeding 4000 pounds per square inchhave been observed during this process. Due to the frozen plug at thetop of annulus 22, pressure measured using transmitter 24 will notindicate this severe pressure rise. Therefore, routine pressuremonitoring at the well head may not help detect the issue. If thepressure in the well rises too much, it may cause an explosion at thetop with leakage to the environment and potentially serious injury oreven death.

Accordingly, it is extremely important to determine whether the outerannulus is becoming, or has become plugged. Further, in order to ensurethat additional costs are not required in this monitoring process, itwould be beneficial if such monitoring could be done without addingsignificant hardware, or technician time.

SUMMARY OF THE INVENTION

Outer annulus plugging detection is provided for gas-lift oil wells. Theouter annulus detection is effected using a pressure transmitter. Thepressure transmitter provides an indication of pressure within an outerannulus of the oil well. A parameter related to a plurality of outerannulus pressure readings is used to provide an indication of annulusplugging. Examples of the statistical parameter include mean andstandard deviation.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is diagrammatic view of a typical gas-lift oil well.

FIG. 2 is diagrammatic view of a pressure transmitter operably coupledto an outer annulus in accordance with an embodiment of the presentinvention.

FIG. 3 shows results from a test performed in accordance with anembodiment of the present invention.

FIG. 4 shows the standard deviation as a function of time for the sametest cases as that of FIG. 3.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

FIG. 2 is diagrammatic view of a pressure transmitter 100 operablycoupled to outer annulus 22. Pressure sensor 102 of transmitter 100 isfluidically coupled to annulus 22 and has an electrical characteristicthat varies with the pressure in annulus 22. Pressure sensor 102 can bea capacitive-type pressure sensor, a resistance-based strain gauge-typesensor, or any other suitable type of sensor. Pressure sensor 102 iselectrically coupled to analog to digital converter 104. Converter 104converts an analog signal from sensor 102 into a digital value that itprovides, via line 106, to controller 108. Additionally, in accordancewith one embodiment of the invention, converter 104 may provide anauxiliary output 110, illustrated in phantom, that simply reflects adigital bitstream indicative of the analog reading. The use of a digitalbitstream allows higher resolution, which is useful for some types ofstatistical processing. For example, while a traditional analog todigital converter may provide digital conversions on line 106 atapproximately 22 times per second, the frequency of the digitalbitstream on line 110 may be over 100 kHz.

Power module 112 can include any suitable circuitry for receiving andconveying power to the components of transmitter 100. Module 112 iscoupled to all components requiring power as indicated at line 114.Module 112 may include an energy storage cell, or may include suitablecircuitry to couple to a source of energy. It is known for some processindustry standard protocols to provide operating power. Examples of suchprotocols include HART, and FOUNDATION™ Fieldbus. Power module 112 mayalso include one or more suitable transducers for converting potentialenergy into electrical energy for transmitter 100. Thus, module 112 mayinclude one or more solar cells, for example.

Communications module 116 is coupled to controller 108 and allowstransmitter 100 to communicate to one or more external devices. Inembodiments where transmitter 100 is expected to communicate using anindustry standard process communication protocol, module 116 will besuitably adapted. For example, if transmitter 100 is to communicateusing the FOUNDATION™ fieldbus protocol, module 116 may include anysuitable known fieldbus communications circuitry. Transmitter 100, insome embodiments, can provide a first signal indicative of pressurewithin annulus 22, and a second signal indicative of annulus plugging.Known protocols allow such signals to be provided over the samecommunication lines. For example, one signal could be provided in analogformat, and the second signal could be a superimposed digital signal.

Controller 108 is preferably a microprocessor. Controller 108 could bepart of transmitter 100, or may reside in a remote location fromtransmitter 100. Controller 108 may include internal memory (notseparately illustrated) and/or may be coupled to external memory 120.Using internal memory, external memory 120, or any combination thereof,controller 108 will store pressure measurement data related to readingsfrom pressure sensor 102 over time. In accordance with embodiments ofthe present invention, it has been determined that secondarycalculations based upon a plurality of temporally spaced readingsrelated to pressure sensor 102 can reveal the plugging of annulus 22.Much of the remainder of the description will focus upon the use ofstatistical parameters. However, embodiments of the present inventioncan be practiced using other analytical techniques such as fuzzy logic,neural networks, learning techniques, trend analysis, and any othersuitable methods, or any combination thereof.

In order to understand the effects of plugging, various simulations wereperformed both on real oil wells and on simulated laboratory rigs. Inthese simulations, various valves on instrument piping were used toartificially induce a plugged annulus condition by isolating themeasurement device from the process. A commercially available pressuretransmitter sold under the trade designation 3051 S T, available fromRosemount, Inc., of Eden Prairie, Minn., was used as thepressure-measuring device. This transmitter was equipped with anauxiliary data channel 110 for providing fast updating diagnostics forstatistical calculations. The two statistical calculations used in thesimulations were mean and standard deviation of the pressuremeasurement. However, embodiments of the present invention should not beconsidered to be limited to such statistical calculations.

FIG. 3 shows results from one of the test performed. This plot presentsthe mean parameter as a function of time. In this particular case, thenormal operating pressure in outer annulus 22 is approximately 426pounds per square inch. Every time that a valve was closed to simulateannulus plugging, the mean parameter pressure reading showed asignificant drop in value compared to normal operating pressure. It hasbeen concluded that the temperature changes and pipe/valve leakscontribute to this change as a result of plugging. Accordingly, pressuretransmitter 100 can be characterized, or otherwise calibrated to a knownnon-plugged condition. Then, if the mean of the pressure sensor readingsdeviates beyond an allowable threshold from the baseline “good”condition, an alarm, or other suitable indication, is provided frompressure transmitter 100 indicating annulus plugging.

FIG. 4 shows the standard deviation as a function of time for the sametest cases of that of FIG. 3. The standard deviation parameter presentsa significantly more distinctive signature for plugging indications.Each time the system was plugged, a peak was observed in the standarddeviation. As is apparent from the results illustrated in FIG. 4,standard deviation may be used alone, or in combination with the mean toprovide annulus plugging detection.

Another challenging situation for annulus plugging detection is when awell is stopped and started. In this case, the pressures in outerannulus 22 will not be as high as during normal operation. However,statistical process monitoring may still be used in this case. Iftraining has been performed on the pressure transmitter before thepumping operation is shut down, then the outer annulus mean pressure andits standard deviation can be recorded as baseline. When the well isstarted again, it is expected that the pressure measurements areexpected to rise from its shutdown levels if there is no plugging. Ifthere is plugging, the pressure measurements will not significantlyrise, thus indicating plugged annulus. Thus, in accordance with oneembodiment of the present invention, pressure transmitter 100 isprovided with a notification regarding pumping operations, eitherstopping, starting, or both. Thus, when pressure transmitter 100receives a notification that pumping is starting again, it may wait apre-selected duration before expecting measurements to be acceptable.

While it is preferred that monitoring of a statistical parameter relatedto the outer annulus pressure be done continuously, embodiments of thepresent invention can be practiced by accessing the outer annuluspressure at selected intervals, or even in response to technicianrequests. However, sufficient numbers of pressure measurements must betaken by pressure sensor 102 in order to provide statisticalcomputations.

Although the present invention has been described with reference topreferred embodiments, workers skilled in the art will recognize thatchanges may be made in form and detail without departing from the spiritand scope of the invention.

1. A system for detecting outer annulus plugging in a gas-lift oil well,the system comprising: a pressure transmitter operably coupleable to theouter annulus of the gas-lift oil well, the pressure transmitter beingadapted to provide a signal related to pressure within the outerannulus; and a controller configured to receive the signal and obtain aplurality of pressure measurements relative to the outer annulus, whichmeasurements are temporally spaced, the controller being configured tocalculate a parameter indicative of annulus plugging based on theplurality of pressure measurements.
 2. The system of claim 1, whereinthe controller is a component of the pressure transmitter.
 3. The systemof claim 1, wherein the pressure transmitter is adapted to provide afirst signal indicative of pressure within the outer annulus, and asecond signal indicative of plugging.
 4. The system of claim 3, whereinthe pressure transmitter communicates over a digital processcommunication loop.
 5. The system of claim 1, wherein the pressuretransmitter is powered by a digital process communication loop.
 6. Thesystem of claim 1, wherein the pressure transmitter further comprises ananalog-to-digital converter providing digital conversions to thecontroller.
 7. The system of claim 1, wherein the pressure transmitterfurther comprises an analog-to-digital converter providing a high-speedbitstream to the controller.
 8. The system of claim 1, wherein theparameter is a statistical parameter.
 9. The system of claim 8, whereinthe statistical parameter is mean.
 10. The system of claim 8, whereinthe statistical parameter is standard deviation.
 11. The system of claim8, wherein the statistical parameter is a combination of mean andstandard deviation.
 12. The system of claim 1, wherein the parameter iscalculated using fuzzy logic.
 13. The system of claim 1, wherein theparameter is calculated using a neural network.
 14. A method ofdetermining whether an outer annulus of a gas-lift oil well is at leastpartially plugged, the method comprising: obtaining a plurality oftemporally spaced pressure measurements within the outer annulus;calculating a statistical parameter using the plurality of measurements;and providing an indication of plugging based upon the statisticalparameter.
 15. The method of claim 14, wherein the method is performedby a pressure transmitter.
 16. The method of claim 14, wherein thestatistical parameter is mean.
 17. The method of claim 14, wherein thestatistical parameter is standard deviation.
 18. A gas-lift oil wellcomprising: a first pipe having a first pipe wall defining an interioradapted to convey pressurized crude oil; a second pipe having a secondpipe wall defining an inner annulus with the first pipe wall; an outershell defining an outer annulus with the second pipe wall; and means fordetecting plugging of the outer annulus.